A lack of pipelines isn't the only thing that has been choking Alberta's oilpatch, Canada's energy regulator says.

The National Energy Board (NEB) has released a report that clarifies what has plagued fossil fuel companies in the oil-rich province over the past year. The economic turmoil persisted as the industry ramped up production in a market with buyers who are paying far less for Alberta crude than what they pay for other petroleum products.

The report said that maintenance and production woes at U.S. refineries were also a key factor affecting the market price for oil produced in Canada, which is home to the world's third largest reserves of crude after Saudi Arabia and Venezuela.

“Demand for crude oil comes from refineries,” the NEB makes clear in its report, released Dec. 27, 2018. Canada depends on U.S. refineries to process its oil, because "three-quarters of the crude oil produced in western Canada" is heavy oil with high amounts of sulphur, yet Canada’s refineries are “largely configured to process light crude."

The largest U.S. refinery purchaser of Canadian heavy oil in the country, BP's Whiting Refinery near Chicago, had a maintenance shutdown last year. The refinery buys roughly 250,000 barrels per day of Canadian crude, according to the Canadian Press.

The new NEB analysis comes at a time when some conservative-leaning politicians have been using the gloomy market reality to attack the left-leaning NDP government in Alberta and the federal Liberal government in Ottawa for failing to fix the problem.

While refiners in the U.S. have invested in equipment to process heavy crude, the board noted, until recently there was no refinery in Canada built specifically for this purpose. There is some capacity at other refineries — Suncor’s Montreal Refinery processed on average 24,300 barrels per day of diluted bitumen, an oilsands product, in 2017.

But the new $9.7-billion Sturgeon Refinery near Edmonton, the first purpose-built for heavy oil, was still in its final stages of startup last month.

The board highlighted data showing how the amount of Western Canada crude oil available for export has only recently exceeded available pipeline capacity, even as the amount of oil available to export more than doubled since 2010.

If Canada's crude oil available for export had not grown as much as it did over the last eight years, pipeline capacity may not have become as much of an issue as it is today, writes @NatObserver reporter @ottawacarl #pipelines #oilsands

Available capacity remained steadily above available crude from January 2010 until September 2018. Meanwhile, crude available for export went from under two million barrels per day, to over four million barrels per day.

Put another way, if Canada's crude oil available for export had not grown as much as it did over the last eight years, pipeline capacity may not have become as much of an issue as it is today.

The report represents the first part of the board's response to a Nov. 30 request by Natural Resources Minister Amarjeet Sohi for “advice” on options to optimize oil exports. It said it sees the report as a "backgrounder" in support of more work to be conducted in early 2019.

As a result, after publishing the report, the NEB launched an online forum to seek public input. It plans to meet this month with oil and gas companies, pipeline operators, governments and others to seek input on questions posed by the minister.

Jason Kenney testifies at the House of Commons Standing Committee on Finance on May 7, 2018, sharing a glance with University of Alberta economist Andrew Leach (left). Photo by Alex Tétreault

Sohi says report shows need for new pipelines

When Alberta Premier Rachel Notley ordered a crude oil production cut of roughly 8.7 per cent in early December, both federal Conservative Party leader Andrew Scheer and provincial United Conservative Party leader Jason Kenney raised the issue of pipeline capacity as central to the issue.

Throughout the second half of 2018, the province faced an unusually large discount on crude bitumen from the oilsands — a heavy oil that gets blended with other Canadian oil products to form a benchmark price called Western Canadian Select (WCS) — relative to another North American crude benchmark, West Texas Intermediate (WTI).

That “decline in the value of Alberta’s resource” was due to a lack of pipelines, Scheer said last month, a “direct result” of Prime Minister Justin Trudeau’s “failures on several major pipeline projects.” Kenney said at the time of Notley’s production cut that it was "more important than ever" to make sure the Trans Mountain pipeline expansion project and TransCanada's Keystone XL pipeline are built.

Kenney was a federal cabinet minister for several years when the government of former prime minister Stephen Harper was in power, failing to get Enbridge's Northern Gateway pipeline to the west coast of B.C. Harper also failed to convince former U.S. president Barack Obama to approve the Keystone XL pipeline to Texas.

Scheer was a Conservative MP under Harper, during those years, serving as speaker of the House of Commons from 2011 to 2015.

Sohi's NEB letter also refers to future pipelines — the Enbridge Line 3 replacement pipeline and the Keystone XL pipeline — as likely to fix “current transportation challenges” over the long term. Line 3, once completed, would ship oil from Hardisty, Alberta to Superior, Wisconsin, while the TransCanada project would send more Canadian oil to the Gulf coast of Texas.

Alberta officials have said the province, which currently produces 3.7 million barrels per day of raw crude and bitumen, is generating 190,000 barrels per day more than it has the ability to ship by pipeline or rail, and storage tanks have become full.

Recently, oil prices have remained elevated, with the price gap sitting at about $12.50 USD per barrel on Jan. 2.

Asked for the minister's reaction to the report, Sohi's press secretary Vanessa Adams thanked the regulator for its work and said the report provided "further evidence for the need to build new pipelines."

"Since day one, our government has been working to support our oil and gas sector and the jobs it creates by making market access a priority," said Adams on Jan. 4.

"It’s why we approved the Line 3 replacement project, which will come online in 2019, and have always supported Keystone XL. It’s also why we made a $4.5 billion investment in Alberta’s energy sector with the Trans Mountain pipeline, and why we are moving forward on the expansion project in the right way through meaningful consultations."

This graph from the NEB shows how there has been sufficient capacity to export available crude oil from January 2010 until September 2018, even as the amount of oil available more than doubled. NEB screenshot

Oil production grows, but pipeline capacity constant

The board's report says the "primary factor" behind the price gap was a "growing supply of Western Canadian oil production" to 4.3 million barrels per day in September 2018, while "takeaway capacity on existing pipeline systems remained constant" at roughly 3.95 million barrels per day.

But it also says “refinery maintenance in the U.S. Midwest, the largest export market for Canadian heavy crude oil, led to a significant reduction in demand for Canadian oil."

Both of these factors "contributed to a backlog of Canadian crude oil, higher levels of oil in storage in Alberta, and a lower price for Canadian crude oil," the report stated.

Last month, Notley issued a call for proposals to build or expand oil refineries either in Alberta, or connected with provincial oil production. Proposals are currently being accepted until Feb. 8, and can be for either new builds or expansions to existing sites.

In his earlier comments, Kenney also noted that the oil price was being forced down by “market manipulation by traders and commodity markets to create the problem of so-called air barrels.”

He was referring to complaints from some industry stakeholders that a major Canadian oil pipeline was running below capacity, due to a flawed regulatory system that was preventing some shippers from getting all the space they needed to send their product to market.

In his own open letter to the NEB, Sohi acknowledged that pipeline capacity “appears to be” constrained by “apportionment levels,” which is a technique of reducing space that pipeline operators use when there is more oil to transport than available space, as well as the growth of oil-by-rail.

He asked the board to consider whether the monthly process to portion out space on oil pipelines was “functioning appropriately” and consistent with the law, and whether there were any “short-term steps” to maximize rail capacity.

The NEB report does say that the average percentage of apportionment increased in 2018. But it does not include the “air barrels” phenomenon in its analysis of the “recent market events” resulting in the price gap this fall.

This graph from the NEB shows how Western Canadian oil has been consistently priced less than another North American benchmark crude since at least 2015. The price gap widened significantly in the latter half of 2018. NEB screenshot

Oil being discounted on 'quality,' transport costs

Canada was the fourth-largest crude oil exporter in the world in 2017, the NEB said, exporting 3.3 million barrels per day. Canadians are also one of the top 10 oil-consuming nations in the world.

The globally accepted scientific consensus is that humanity must severely cut back on its production and consumption of fossil fuels like oil, natural gas and coal, which emit carbon pollution that collect in the atmosphere, trapping heat and warming the planet.

The Intergovernmental Panel on Climate Change says the planet has less than 12 years to take action to reduce pollution to levels that avoid heightened risk of severe floods, droughts, extreme heat and poverty.

Carbon pollution is causing significant and irreversible damage to ecosystems, and will disproportionally impact the poor, degrade human health and lead to water scarcity, according to a Congressionally-mandated report released last year, involving a wide range of U.S. government agencies and departments. The report projected that climate change will cost the U.S. economy hundreds of billions of dollars.

Forms of energy that pollute less will eventually need to become the dominant form of primary energy for industrial, commercial and personal use. No more than one-third of proven reserves of fossil fuels can be consumed prior to 2050, the International Energy Agency has concluded based on peer-reviewed evidence, unless carbon capture technology is deployed.

The majority of crude oil produced in Canada is from the Western Canadian Sedimentary Basin, an area stretching over almost all of Alberta and some of Manitoba and Saskatchewan. Most of that production is a heavy oil that is high in sulphur.

Even before the widening price gap this fall, Western Canadian Select typically traded at a discount to West Texas Intermediate. Between 2015 and 2017, the difference between the two crudes averaged $12.95 USD per barrel.

WCS is priced relative to WTI because Western Canadian oil crude is refined in the U.S., and "Canadian crudes are commonly priced relative to crude oils in the markets where they compete for refining capacity," the report stated.

The board said "two major components comprise the oil price differential in a balanced market," namely a difference in "quality," and transportation costs.

"Heavy crudes are lower quality than light crudes because they yield a lower amount of high value end-products, like gasoline and diesel," said the board. "Heavy crude oil is also more costly to refine compared to light crude oil."

As well, crude oil with more sulphur, which Canada produces, "require additional refining steps and costs."

The two types of crudes also have different transportation costs built in to their price, said the regulator.

"Crude oil that is physically located closer to major refinery regions will sell for more than crude oils located further from refineries. This price difference reflects the additional cost to transport the crude oil to the refineries."

Alberta Premier Rachel Notley in Ottawa at a luncheon event held by Canada Club, at the Chateau Laurier, on Nov. 28, 2018. Photo by Alex Tétreault

Mainline 'inherently' harder to run at capacity

Notley’s production cut is expected to last until Alberta's storage tanks have been drawn down, a process that is projected to take about three months, after which the amount of production being cut will be reduced.

Unlike the production cut, however, provincial officials say Notley's plan to boost the amount of oil that moves by rail will take longer to kick in, with the first 15,000 barrels of extra rail capacity available starting December 2019.

Oil is currently taking up a bit more than six per cent of rail freight volume in Canada, but rail capacity can't be brought on quickly, according to the energy regulator, unless appropriate loading and unloading infrastructure, train crews, and specialized tank cars already exist and are ready to be deployed.

In the meantime, "companies wishing to transport their oil production by rail are competing for rail space with many other commodities," the NEB wrote.

As for the "air barrels" issue, the regulator noted that the Enbridge Mainline, the largest crude oil transportation system, is "inherently more difficult to operate at full capacity because of size and system optimization complexities."

It said it would explore that issue further in its next report to Sohi.

The board also noted that when apportionment occurs, some shippers can "engage in trades in the secondary market." That might "add complexity to the nomination process and the subsequent operation of the pipeline," it said.

Oilpatch player Canadian Natural Resources raised concerns on Dec. 5 of a “dysfunctional pipeline nomination process." Enbridge told analysts that month it would boost its capacity by as much as 100,000 barrels per day by the middle of 2019 and review how it runs its central pipeline, the Mainline.

The company told media in November that the Mainline “is essentially full” and that "there is no material capacity to be gained by changing the apportionment and supply verification procedures.”

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Pipeline capacity in the U.S. is also full as the U.S. is now the largest producer of crude oil in the world. In January 2015, the U.S. federal government lifted the ban on crude oil exports to foreign countries. It is said that the U.S. could add around 4 million barrels per day (mb/d) of additional supply in the coming years.
Most of the new supply will come in the form of light sweet and ultra-light oil which fetch higher prices on the international market than the Canadian heavy crude oil that cost more to refine ( Gulf Coast refineries are largely equipped to handle medium and heavy crude). The U.S. crude oil producers can sell their crude at a lower price than Brent which has opened an international market for U.S. crude oil.
(source: Oil Price, Mar 07, 2018:" U.S. Oil Export Boom Boosts Pipeline Demand")
According to the U.S. Energy Information Administration (EIA), exports of U.S. crude oil to foreign countries (including Canada) has reached 2,326,000 b/d in October of this year, or around 21.5% of U.S. total oil production. The main recipients over the last year have been China, South Korea, India, and other European countries. Canada continues to represent a major export destination for U.S. crude oil (468,000 b/d in last October) but went from representing 94% of U.S. oil exports in 2014 to around 30% in 2017 (20.1% in October).
As the U.S. is becoming a major player on the world market, the prospect for Canada's oil exports to foreign countries other than the U.S. is looking bleaker and bleaker as the large majority of oil refineries around the world are not equipped to process Canada's heavy crude oil (Canada's exports to countries other than the U.S. which represents around 0.8% of Canada's total production, is composed of light crude oil), and building new refining capacity in Canada to process Alberta's heavy crude revealed itself to be very expensive. Building new oil pipelines to the pacific or the atlantic coast would be a very risky investment as future markets for Canada's crude oil are and will be in the U.S. The problem with Alberta's oil is overproduction, not pipeline capacity.